A variety of processes are used to recover viscous hydrocarbons, such as heavy oils and bitumen, from underground deposits. There are extensive deposits of viscous hydrocarbons around the world, including large deposits in the Northern Alberta tar sands, that are not amenable to standard oil well production technologies. The primary problem associated with producing hydrocarbons from such deposits is that the hydrocarbons are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. In some cases, such deposits are mined using open-pit mining techniques to extract the hydrocarbon-bearing material for later processing to extract the hydrocarbons.
Alternatively, thermal techniques may be used to heat the reservoir to produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a single horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Pat. No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.
One thermal method of recovering viscous hydrocarbons using two vertically spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD is currently the only commercial process that allows for the extraction of bitumen at depths too deep to be strip-mined. By current estimates the amount of bitumen that is available to be extracted via SAGD constitutes approximately 80% of the 1.3 trillion barrels of bitumen in place in the Athabasca oilsands in Alberta, Canada. Various embodiments of the SAGD process are described in Canadian Patent No. 1,304,287 and corresponding U.S. Pat. No. 4,344,485. In the SAGD process, steam is pumped through an upper, horizontal, injection well into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well vertically spaced proximate to the injection well. The injector and production wells are typically located close to the bottom of the hydrocarbon deposit.
It is believed that the SAGD process works as follows. The injected steam creates a ‘steam chamber’ in the reservoir around and above the horizontal injection well. As the steam chamber expands upwardly and laterally from the injection well, viscous hydrocarbons in the reservoir are heated and mobilized, especially at the margins of the steam chamber where the steam condenses and heats a layer of viscous hydrocarbons by thermal conduction. The mobilized hydrocarbons (and aqueous condensate) drain under the effects of gravity towards the bottom of the steam chamber, where the production well is located. The mobilized hydrocarbons are collected and produced from the production well. The rate of steam injection and the rate of hydrocarbon production may be modulated to control the growth of the steam chamber to ensure that the production well remains located at the bottom of the steam chamber in an appropriate position to collect mobilized hydrocarbons. Typically the start-up phase takes three months or more before communication is established, depending on the formation lithology and actual interwell spacing. There exists a need for a way to shorten the pre-heating period without sacrificing SAGD production performance.
It is important for efficient production in the SAGD process that conditions in the portion of the reservoir spanning the injection well and the production well are maintained so that steam does not simply circulate between the injector and the production wells, short-circuiting the intended SAGD process. This may be achieved by either limiting steam injection rates or by throttling the production well at the wellhead so that the bottomhole temperature at the production well is below the temperature at which steam forms at the bottomhole pressure. While this is advantageous for improving heat transfer, it is not an absolute necessity, since some hydrocarbon production may be achieved even where steam is produced from the production well.
A crucial phase of the SAGD process is the initiation of a steam chamber in the hydrocarbon formation. The typical approach to initiating the SAGD process is to simultaneously operate the injector and production wells independently of one another to recirculate steam. The injector and production wells are each completed with a screened (porous) casing (or liner) and an internal tubing string extending to the end of the liner, forming an annulus between the tubing and the casing. High pressure steam is simultaneously injected through the tubings of both the injection well and the production well. Fluid is simultaneously produced from each of the production and injection wells through the annulus between the tubing string and the casing. In effect, heated fluid is independently circulated in each of the injection and production wells during this start-up phase, heating the hydrocarbon formation around each well by thermal conduction. Independent circulation of the wells is continued until efficient fluid communication between the wells is established. In this way, an increase in the fluid transmissibility through the inter-well span between the injection and production wells is established by conductive heating. Once efficient fluid communication is established between the injection and the production wells, the injection well is dedicated to steam injection and the production well is dedicated to fluid production. Canadian Patent No. 1,304,287 teaches that in the SAGD start-up process, while the production and injection wells are being operated independently to inject steam, steam must be injected through the tubing and fluid collected through the annulus, not the other way around. It is disclosed that if steam is injected through the annulus and fluid collected through the tubing, there is excessive heat loss from the annulus to the tubing and its contents, whereby steam entering the annulus loses heat to both the formation and to the tubing, causing the injected steam to condense before reaching the end of the well.
The requirement for injecting steam through the tubing of the wells in the SAGD start-up phase can give rise to a problem. The injected steam must travel to the toe of the well, and then migrate back along the well bore to heat the length of the horizontal well. At some point along the length of the well bore, a fracture or other disconformity in the reservoir may be encountered that will absorb a disproportionately large amount of the injected steam, interfering with propagation of the conductive heating front back along the length of the well bore.
U.S. Pat. No. 5,407,009 identifies a number of potential problems associated with the use of the SAGD process in hydrocarbon formations that are underlain by aquifers. The U.S. Pat. No. 5,407,009 teaches that thermal methods of heavy hydrocarbon recovery such as SAGD may be inefficient and uneconomical in the presence of bottom water (a zone of mobile water) because injected fluids (and heat) are lost to the bottom water zone (“steam scavenging”), resulting in low hydrocarbon recoveries. U.S. Pat. No. 5,407,009 also addresses this problem using a technique of injecting a hydrocarbon solvent vapour, such as ethane, propane or butane, to mobilize hydrocarbons in the reservoir.
There have been efforts to promote methods that reduce the start-up time in SAGD production such as U.S. Pat. No. 5,215,146. U.S. Pat. No. 5,215,146 describes a method for reducing the start-up time in SAGD operation by maintaining a pressure gradient between upper and lower horizontal wells with foam. By maintaining this pressure gradient hot fluids are forced from the upper well into the lower well. However, there exists an added cost and maintenance requirement due to the need to create foam downhole, an aspect that is typically not required in SAGD operation.
Other methods, initiate the recovery of viscous hydrocarbons from underground deposits by injecting heated fluid into the hydrocarbon deposit through an injection well while withdrawing fluids from a production well. when such a method is utilize the flow of heated fluid between the injection well and the production well raises the temperature of the reservoir between the wells to establish appropriate conditions for recovery of hydrocarbons. However, there exists an added cost and maintenance requirement due to the need to injected heated fluid downhole, an aspect that is not required in typical SAGD operation
There exists a need for a method to reduce the start-up time in a SAGD operation that does not require foam or the need for injecting fluids downhole.